Removal of acidic gases in a gasification power system with production of hydrogen

ABSTRACT

This invention is an integrated process which removes acidic gases such as H 2  S, COS and CO 2  from raw synthesis gas. The H 2  S and COS is concentrated and separately recovered. The separately recovered CO 2  is used as a moderator with the purified syngas in a combustion turbine. The process comprises separating H 2  S and COS from a raw synthesis gas by absorption with a liquid solvent, removing coabsorbed CO 2  by stripping the solvent with nitrogen, separating the H 2  S and COS from the solvent and recovering sulfur from the H 2  S and COS. The energy value of the CO 2  and its value as a diluent in reducing NO x  is recovered by using the CO 2  as a moderator during combustion of the purified synthesis gas in a gas turbine.

BACKGROUND OF THE INVENTION

This application claims the benefit of U.S Provisional Application No.60/058,748 filed Sep. 12, 1997.

1. Field of the Invention

This invention relates to gasification power generating systems whereina hydrocarbonaceous fuel is partially oxidized in a gasifier to producea synthesis gas or syngas which can be used as a fuel in a combustionturbine to produce power, and more specifically to a process for theselective removal of H₂ S and COS from the syngas while retaining thevalues associated with CO₂ and other gases for power production. It alsorelates to a process for removing CO₂ from the hydrogen content of thesyngas.

2. Description of the Prior Art

H₂ S and COS are generally removed from the syngas produced by thepartial oxidation of a hydrocarbonaceous fuel before the syngas isburned as a high pressure fuel gas in a combustion turbine to drive agenerator and produce power. One technique utilizes physical or chemicalabsorption with a liquid solvent, as disclosed in U.S. Pat. No.5,345,756 to Jahnke et al. In the process of removing the H₂ S and COSfrom the syngas, other acid gases, such as CO₂, are undesirably removedwith the H₂ S and COS. The retention of CO₂ is desirable because itspresence in the high pressure fuel gas generates power when it isexpanded in the gas turbine.

Hydrogen is a component of the synthesis gas produced by the partialoxidation of a hydrocarbonaceous fuel. The synthesis gas is purifiedbefore use. See U.S. Pat. No. 5,152,975 to Fong et al. Procedures forsuch purification would be more efficient if the CO₂ present in thehydrogen stream could be removed from the hydrogen prior topurification.

To achieve desired SO₂ emission limits, approximately 97% of H₂ S+COSmust be removed and recovered, typically as elemental sulfur in a Clausplant.

Early attempts to use N₂ to strip coabsorbed CO₂ from physical solventswere either at high pressure, at essentially the same pressure as the H₂S absorption, or at essentially atmospheric pressure. Because thestripping gas requirement increases in direct proportion to pressure,compressing the increased quantity of N₂ to the higher pressure wasconsidered to be practicable only in the case where NH₃ is beingproduced and the N₂ compression is already required.

A N₂ stripping stage to enrich the Claus plant acid gas feed has beenused for some time. In one process, it operates at essentiallyatmospheric pressure and includes a bottom CO₂ stripping sectionsurmounted by an H₂ S reabsorber section. In operation it uses N₂ tostrip some CO₂ from the solvent. H₂ S in the stripped CO₂ is reabsorbedwith an H₂ S solvent to give an N₂ plus CO₂ vent stream containing anacceptable amount of about 10 ppm of H₂ S. While operation at lowpressure minimizes the N₂ stripping gas requirement which is directlyproportional to pressure, it increases the solvent flow required toreabsorb the H₂ S which is inversely proportional to operating pressure.Because the reabsorbtion solvent flow is generally added to the mainabsorber solvent for regeneration, it increases the regeneration steamrequirement. As a result, N₂ stripping at low pressure to obtain aconcentrated Claus H₂ S stream is unattractive because regenerationsolvent flows are excessive and result in prohibitive solventregeneration steam and refrigeration requirements. Also, the strippedcarbon dioxide along with the nitrogen strip gas is vented to theatmosphere and does not contribute to power production in the combustionturbine.

A selective acid gas removal process is required to absorb essentiallyall the H₂ S while coabsorbing a minimum amount of CO₂. Minimum CO₂removal is required to obtain a concentrated H₂ S Claus plant feed tominimize the capital and operating costs of the Claus plant.Co-absorption of CO₂ not only dilutes the Claus H₂ S feed, it alsodecreases the integrated gasification combined cycle (IGCC) powergeneration thermal efficiency. Since the CO₂ in the high pressure fuelgas generates power when it is expanded in the gas turbine, its removalwith the H₂ S loses that power generation potential.

The problem is that available acid gas removal processes are notsufficiently selective and co-absorb significant CO₂. The most selectivephysical solvents, such as mixed dialkylethers of polyethylene glycoland N methyl pyrrolidone coabsorb over 15% of the CO₂ when solvent flowis set to remove essentially all of the H₂ S. This results in a verydilute acid gas which cannot be processed in a conventional Claus plant.In commercial practice an expensive H₂ S selective aminepreconcentration is used to increase the Claus feed to 25% H₂ S. Even atthis concentration the purification is very expensive.

U.S. Pat. No. 4,242,108 to Nicholas et al solves the problem ofobtaining a concentrated Claus H₂ S feed gas by a process utilizing anH₂ S absorber, a CO₂ absorber, a H₂ S stripper and tho CO₂ strippers.The process involves heating the H₂ S absorber bottoms solvent andfeeding it to a high pressure CO₂ stripping column operating atessentially the same pressure as the H₂ S absorber and stripping thecoabsorbed CO₂ with a high pressure CO₂ -free inert gas. Nicholas et alnotes the possibility of using high pressure N₂ from an air separationunit, however, this disclosure of N₂ use appears limited to NH₃applications where N₂ has to be compressed and added to the H₂ afteracid gas removal to make NH₃ synthesis gas. This application merelyroutes a portion of the required N₂ through the stripper for beneficialeffects and appears limited to situations where CO₂ is rejected from theproduct gas as in NH₃ synthesis. A major problem with this process isthe loss of CO₂ which is vented after being flashed off and the loss ofCO₂ and N₂ from the second CO₂ stripper.

U.S. Pat. No. 4,568,364 to Galstaun et al discloses the advantage ofadding carbon dioxide to a fuel gas for a gas turbine to decrease excessair compression with resultant increase in turbine net power. Alsodiscussed is the advantage in low sulfur coal gasification applicationsof using nitrogen to strip coabsorbed carbon dioxide from hydrogensulfide loaded solvent to obtain, after final hydrogen sulfidestripping, an acceptably concentrated hydrogen sulfide Claus feed gas.Galstaun's process, however, depends on using the selective hydrogensulfide/carbon dioxide physical solvent acid gas removal system of anadjacent operation producing hydrogen to get the combined advantages ofcarbon dioxide addition to the fuel gas and the use of nitrogenstripping to obtain a concentrated Claus hydrogen sulfide feed gas.Galstaun imports carbon dioxide into the fuel gas stream by using carbondioxide loaded solvent from the adjacent hydrogen plant carbon dioxideremoval step. Galstaun does not recover coabsorbed carbon dioxideflashed or stripped with nitrogen from the hydrogen sulfide loadedsolvent into the fuel gas. Nor does Galstaun recover nitrogen used forstripping into the fuel gas to produce the same advantages in theturbine operation that the carbon dioxide does. Because Galstaun'snitrogen stripper effluent is inevitably contaminated with hydrogensulfide, it cannot be vented to the atmosphere. Therefore, the gas issent to the adjacent carbon dioxide stripper where the containedhydrogen sulfide is reabsorbed for recovery.

U.S. Pat. Nos. 4,957,515 and 5,240,476, both to Hegarty, offer asolution to the problem of obtaining a concentrated H₂ S feed to a Clausunit while retaining the CO₂ content of the syngas as feed to the gasturbine to maximize power recovery. Hegarty uses a small amount of N₂under pressure to strip coabsorbed CO₂ from the rich physical solventfor recycle to the fuel gas, free of H₂ S.

In both Hegarty patents, the H₂ S and CO₂ rich solvent from the H₂ Sabsorber bottoms, at about 500 psia, is used to drive a turbine toreduce the pressure to about 90 psia, after which the solvent isstripped of CO₂ using N₂ in a CO₂ stripper operated at 78 psia. Thegases from the stripper are recycled while the H₂ S laden solvent issent to an H₂ S stripper. In the '476 Hegarty patent the CO₂ rich gasesare recompressed and sent directly to the single H₂ S absorber. In the'515 Hegarty patent the recompression step is replaced by reabsorptionof H₂ S in a secondary H₂ S absorber. The CO₂ values are absorbed in asolvent and the solvent recycled to the H₂ S absorber; the H₂ Scontaminated nitrogen stripping gas is vented. Nitrogen used in the CO₂stripper is also vented.

These processes respectively suffer from the energy need to recompressthe CO₂ rich recycle to the H₂ S absorber from 78 psia to 500 psia andfrom the venting of N₂ to the atmosphere.

What is needed is a purification process that yields a concentrated H₂ SClaus feed, that retains the value of CO₂, and that does not requireexcessive pressure changes, or process heating or refrigeration.

SUMMARY OF THE INVENTION

This invention is an integrated process which removes acidic gases suchas H₂ S, COS and CO₂ from raw synthesis gas. The H₂ S and COS isconcentrated and separately recovered. The separately recovered CO₂ isused as a moderator with the purified syngas in a combustion turbine.The process comprises separating H₂ S and COS from a raw synthesis gasby absorption with a liquid solvent, removing coabsorbed CO₂ bystripping the solvent with nitrogen, separating the H₂ S and COS fromthe solvent and recovering sulfur from the H₂ S and COS. The energyvalue of the CO₂ and its value as a diluent in reducing NO_(x) isrecovered by using the CO₂ as a moderator during combustion of thepurified synthesis gas in a gas turbine.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram showing the removal of H₂ S from thesynthesis gas product from a gasifier.

FIG. 2 is a schematic diagram showing improved H₂ S gas removal using ahigh pressure flash drum.

FIG. 3 is a schematic diagram showing the removal of H₂ S in anintegrated acid gas removal unit.

Corresponding reference numbers indicate corresponding parts in each ofthe figures.

DESCRIPTION OF THE PREFERRED EMBODIMENTS

The present invention comprises a process for removing acid gases suchas H₂ S and COS from synthesis gas before the synthesis gas is burned asa fuel in a combustion turbine to drive a generator and produce power.The H₂ S and COS are removed as undesirable contaminants from thesynthesis gas while other acid gases, such as CO₂ are retained in thefuel streams fed to the combustion turbine.

In one embodiment, the CO₂ loss is reduced to a very low level by theuse of a solvent for acid gases to remove acid gases from the syngasfollowed by the use of N₂ at an intermediate pressure of 300 psig,±100psig, preferably 300 psig±50 psig, to strip the solvent of absorbed CO₂.

Clean solvent is regenerated by removal of H₂ S by steam reboiling andrecycled. The nitrogen stream, containing CO₂ and some H₂ S is washedwith clean solvent. The H₂ S-free stream of nitrogen and CO₂ is utilizedin the combustion turbine. The H₂ S is sent to a Claus unit for furtherprocessing.

This invention also comprises operative steps for removing CO₂ fromhydrogen produced by partial oxidation of a hydrocarbonaceous fuel andsubsequent shift conversion to form shifted syngas.

In a gasification power system wherein a hydrocarbonaceous fuel ispartially oxidized to produce a synthesis gas or syngas from agasification reactor or gasifier at a pressure of about 1000 psig±300psig, preferably about 1000 psig±150 psig, the raw synthesis gas exitingthe gasifier primarily comprises H₂, CO, CO₂, H₂ O, and to a lesserextent N₂, Ar, H₂ S, COS, CH₄, NH₃, HCN, HCOOH. Environmental concernsrequire the removal of H₂ S and COS from syngas that will be burned in acombustion turbine.

In removing H₂ S and COS from syngas, it is desirable to minimizeremoval of other acidic gases, such as CO₂ to avoid dilution of the H₂ Sstream sent to the Claus unit and to maximize the amount of CO₂ sent tothe combustion turbine. Increasing the CO₂ to the combustion turbineincreases the power produced as the CO₂ is expanded in the combustionturbine and at the same time, minimizes oxides of nitrogen (NO_(x))formation by lowering the combustion flame temperature.

This separation is accomplished by sending the syngas to an acid gasrecovery unit where it is treated in a first H₂ S absorber which uses aliquid solvent for the removal of H₂ S. Significant amounts of CO₂ arealso removed by the H₂ S solvent in the first H₂ S absorber, even thoughthe high pressure in the absorber reduces solvent circulation. Torecover the CO₂ absorbed in the acid gas solvent, also referred to asthe "rich solvent," the rich solvent is heated and the pressure reducedto about 300 psig to desorb the CO₂.

The flashed solvent is sent to a N₂ stripper to remove additional CO₂.At 300 psig, the desorbed CO₂ and stripping nitrogen can be fed to thecombustion turbine without further compression as a diluent to controlNO_(x) and to increase power output. Diluent N₂ is normally producedfrom an air separation unit for that purpose and is readily availablefor stripping at the required pressure.

Because a small amount of H₂ S is stripped with the CO₂ in the N₂stripper, the stripped H₂ S is reabsorbed from the N₂ in a secondary H₂S absorber.

It is to be understood throughout this disclosure that the removal of H₂S also encompasses the removal of COS unless otherwise specified.

In accordance with one embodiment of the present invention, CO₂ removalis reduced to a very low level by the use of N₂ at intermediate pressureto strip the acid gas solvent of absorbed CO₂.

With reference to FIG. 1, a sour unshifted synthesis gas or syngas 4principally comprising H₂, CO, CO₂ and H₂ S at a temperature of 200°F.±125° F., typically 150° F.±50° F., a pressure of 1500 psig±1000 psig,typically 1100 psig±400 psig, enters heat exchanger 5 where it is cooledto a temperature of about 90° F.±50° F., typically 110° F.±10° F., andexits as stream 6. The term "sour" refers to a synthesis gas containingsulfur, whereas the term "sweet" refers to a synthesis gas wherein thesulfur content has been removed.

The cooled unshifted sour syngas stream 6 enters the first H₂ S absorber2 at a pressure of about 1000 psig wherein it contacts a chemical orphysical solvent for acid gases, preferably a physical solvent such asmethanol and N-methyl pyrrolidone, and most preferably dimethyl ether ofpolyethylene glycol, available commercially as SELEXOL® (Union Carbide).The temperatures and pressures shown are based on SELEXOL® and may varysignificantly for other solvents.

The sulfur-containing gases such as H₂ S and COS are removed. Thecleaned, unshifted, sweet syngas 8, at a temperature of about 60° F. toabout 130° F. exits H₂ S absorber 2 and enters heat exchanger 5 inindirect heat exchange with the sour unshifted syngas 4.

The warmed clean unshifted syngas 10 comprising H₂, CO and some CO₂ at apressure of about 1000 psig exits heat exchanger 5 and is directed tothe combustion turbine (not shown) after being saturated with water,heated and expanded to the proper conditions for combustion in theturbine.

The liquid stream of H₂ S rich solvent, including some absorbed CO₂,exits the first H₂ S absorber 2 via line 12 and can be optionallycombined with recycle solvent 16 exiting the second H₂ S absorber 14.The combined solvent 17 is preheated in heat exchanger 18 beforeentering the CO₂ stripper 20 through line 22. Solvent stream 16 exitsthe second H₂ S absorber 14. A portion or all of the solvent streamrepresented by line 24 can be separated and combined with the stream 22of H₂ S rich solvent entering the CO₂ stripper 20. A pressure reductiondevice 26 reduces the pressure to about 300 psig, which are the pressureconditions at which the stripper 20 operates.

CO₂ removal is accomplished by nitrogen stripping. Nitrogen gas stream28 at a pressure of about 300 psig enters the CO₂ stripper 20 and stripsor desorbs the CO₂ and a small amount of H₂ S from the solvent beforeexiting the stripper 20 through line 30.

Because a small amount of H₂ S is stripped with the CO₂, the CO₂ and H₂S containing nitrogen stream 30 from the CO₂ stripper 20 is sent to thesecond H₂ S absorber 14 where the H₂ S content is reabsorbed in asolvent. The CO₂ and H₂ S containing N₂ stream 30 can be fed directly tothe second H₂ S absorber 14, or a portion or all of the CO₂ and H₂ Scontaining N₂ stream represented by line 36 can be separated and cooledin heat exchanger 32 and combined with the uncooled portion 34 beforeentering the second H₂ S absorber 14. The second H₂ S absorber 14 andthe CO₂ stripper 20 operate at the same pressure and can be combinedinto one vessel.

Solvent 38 enters the secondary H₂ S absorber 14 and removes the H₂ Sfrom the entering CO₂ and H₂ S containing nitrogen stream. Nitrogenstream 40, removed of the H₂ S and containing CO₂ exits via line 40, andis passed through heat exchanger 41. The CO₂ -rich nitrogen stream exitsvia line 42 at a pressure of about 300 psig±100 psig, preferably about300 psig±50 psig, and can be fed to the combustion turbine withoutfurther compression as a diluent to control NO_(x) and increase poweroutput. Diluent N₂ is normally produced from an air separation unit (notshown) for that purpose and is readily available for stripping at therequired pressure.

Semi-rich solvent 16 containing H₂ S, exits the second H₂ S absorber 14and can be recycled totally or in part to either the first H₂ S absorber2 via line 44, or combined with the solvent 12 exiting the first H₂ Sabsorber 2 to form stream 17, or separated via line 24 and combined withthe preheated solvent 22 entering CO₂ stripper 20. Pump 15 increases thepressure of the solvent stream 16 exiting H₂ S absorber 14 from about300 psig to about 1000 psig. All or a portion of the solvent streamenters the first H₂ S absorber 2 via line 44 or it can be combined vialine 19 with the solvent 12 exiting the first H₂ S absorber.

The H₂ S-containing solvent 48 exiting the CO₂ stripper 20 is thenpassed to the H₂ S stripper 46. The H₂ S-containing solvent 48 is heatedin heat exchanger 50 and enters the H₂ S stripper 46 via line 52.Because N₂ is only slightly absorbed in the solvent, the N₂ content ofthe H₂ S-containing solvent 52 is minimal. Thus, a highly concentratedH₂ S product stream 64 for a Claus or other sulfur processing unit isproduced. The solvent 58 stripped of H₂ S exits H₂ S stripper 46, andafter passing through pump 54 and heat exchangers 18 and 60 can berecycled to the first H₂ S absorber via line 37 and to the second H₂ Sabsorber via line 38.

The temperature within the CO₂ stripper 20 may be controlled at itsoptimum level of about 150° F. to about 250° F. by recovering part ofthe heat from the solvent 58 exiting H₂ S stripper 46 and passingthrough heat exchanger 18. Another option is for all or a portion ofsolvent stream 58 to pass through heat exchanger 50 in counter-currentexchange with the solvent 48 exiting the CO₂ stripper 20, beforeentering heat exchanger 18.

In H₂ S stripper 46 the solvent is reboiled with steam in indirect heatexchanger 80 via line 78 to strip H₂ S. The H₂ S exits overhead via line64 where it is cooled in heat exchanger 66 to condense water. The mixedliquid vapor stream enters separator 70 via line 68 where a portion ofthe liquid H₂ O leaves via line 72 and the H₂ S rich product leaves vialine 74 to the Claus unit (not shown). A portion of the H₂ O is recycledvia line 76 to maintain the desired H₂ O-solvent balance.

FIG. 2 shows an alternative configuration for improved gas removal usinga high pressure flash drum operating at a pressure of 1000 psig±300psig, preferably about 1000 psig±150 psig. The solvent is flashed at atemperature of about 150° F. to about 250° F. This embodiment recoversmore CO₂ at higher pressure and will reduce the size of the secondary H₂S absorber 14.

In this embodiment solvent 12 with acidic gases exits the first H₂ Sabsorber 2 through the pump 11 and exits heat exchanger 18 as preheatedsolvent stream 22. Instead of flowing directly to the CO₂ stripper,stream 22 is diverted to a flash drum 82 where about 5% to 25% of the H₂S and about 10% to 70% of the CO₂ are flashed off. The acid gas depletedsolvent flows to the CO₂ stripper 20 through line 56. The flashed gases85 are returned to the first H₂ S absorber 2 and combined with the sourunshifted gas 4, after being cooled in exchanger 84 and exiting via line86.

It is sometimes desired to produce large quantities of hydrogen alongwith power from a gasification unit. In such instances a portion of thesyngas from the gasifier is shifted to hydrogen in a reactor accordingto the reaction CO+H₂ O→CO₂ +H₂. See for example U.S. Pat. No. 5,152,975to Fong et al., incorporated herein by reference. The remainder of thesyngas is cooled without shifting and, after further processing, sent toa combustion turbine.

The shifted gas is purified by a number of conventional means. One ofthe most efficient techniques utilized to purify the shifted gas is bymeans of a pressure swing absorption (PSA) process which removesimpurities by use of a pressure change on the adsorbent beds. Theshifted gas unfortunately contains a large quantity of CO₂. This isundesirable since the CO₂ reduces the recovery of the hydrogen in thePSA. Furthermore, since CO₂ has no heating value, its presence in thePSA tail gas diminishes the heating value of the tail gas.

Other techniques of H₂ purification, such as methanation, also operatemore efficiently when there is full removal of CO₂ from the shifted gas.

For production of power, it is desirable to have CO₂ in the syngas sinceit helps reduce NO_(x) formation by lowering the combustion flametemperature and also provides power as it runs through the expander sideof the combustion turbine.

A novel and effective technique of accomplishing CO₂ removal andconcentration is to combine the use of a physical solvent or othersuitable solvent for acid gases to remove the CO₂ from the shifted gasto be fed to the PSA or other purification process while maximizing thecontent of CO₂ in the syngas used to fuel the combustion turbine.

This is accomplished by combining the above features in the processingsteps shown in FIG. 3.

Referring to FIG. 3, H₂ S and CO₂ depleted shifted gas, consistingprimarily of hydrogen, is produced from sour shifted syngas which hasbeen subjected to H₂ S removal in shifted gas H₂ S absorber 90 and CO₂removal in CO₂ absorber 104.

The sour shifted gas 109 from the gasifier (not shown) enters shiftedgas H₂ S absorber 90 through heat exchanger 110 and line 112. The H₂ Sdepleted gas leaves the H₂ S absorber 90 via line 114, is combined withsolvent stream 116 from pump 115 and the CO₂ absorber 104, is cooled inheat exchanger 118 and enters CO₂ absorber 104 via line 120. In CO₂absorber 104 the syngas 120 is contacted with clean solvent recycle fromthe sweet CO₂ stripper 100 via pump 101 and line 92 and cooled cleansolvent from the H₂ S stripper 46 via lines 58 and 121. The H₂ S and CO₂depleted product gas 111, containing mostly hydrogen, is sent to the PSAor other purification procedure via line 122 and heat exchanger 110.

A CO₂ rich nitrogen stream 108 suitable as a diluent feed to thecombustion turbine (not shown) is produced from shifted syngas byremoving H₂ S in a shift gas H₂ S absorber 90, followed by solventabsorption of CO₂ in the H₂ S depleted syngas from exit stream 114 inthe CO₂ absorber 104 and nitrogen stripping of the CO₂ rich solvent 106in the sweet CO₂ stripper 100.

A portion 128 of the CO₂ rich solvent 124 exiting the CO₂ absorber 104is recycled to the first H₂ S absorber 2 and a portion 130 is recycledto the shift gas H₂ S absorber 90 where it absorbs H₂ S.

There are three distinctive features to the combined process.

The first feature takes the CO₂ /H₂ S-rich solvent from the bottom ofthe shifted gas H₂ S absorber 90 and introduces it via line 88 into thelower part of the first H₂ S absorber 2, which is also referred to asunshifted gas H₂ S absorber 2. Because the unshifted gas has a muchlower CO₂ content and partial pressure than the CO₂ /H₂ S-rich solvent,the unshifted gas H₂ S absorber 2 strips the CO₂ from the CO₂ /H₂ S-richsolvent.

The second feature heats the CO₂ /H₂ S-rich solvent 12 from theunshifted gas absorber 2 and strips the rich solvent 22 with asufficient amount of nitrogen or other suitable stripping gas to desorbthe CO₂ from the CO₂ stripper 20 operated at about 1000±150 psig. TheCO₂ /H₂ S-rich solvent leaves the first H₂ S absorber 2 via pump 11 andline 12, is preheated in heat exchanger 18 and enters the CO₂ stripper20 via line 22. Nitrogen at about 1000 psig enters line 28. The CO₂stripper 20 reduces the CO₂ content in the CO₂ /H₂ S-rich solvent priorto sending the solvent 48 to the H₂ S stripper 46 through optional heatexchanger 50 and line 52. The CO₂ containing nitrogen stream 94 isrecycled to the first H₂ S absorber 2 through heat exchanger 96 and line98 where it is combined with the raw, unshifted syngas feed 4 and isultimately recovered as part of the syngas product 10 passing to thecombustion turbine (not shown) wherein the CO₂ /N₂ gas mixture functionsas a moderator.

The third feature utilizes a CO₂ absorber 104 on the sweet shifted gas122 which eventually passes to the PSA (not shown) or other H₂purification process as stream 111. Normally such a CO₂ absorber wouldrely primarily on pressure differential to regenerate the solvent andvent the CO₂ at atmospheric pressure. However, in this invention the CO₂rich solvent 106 exiting the CO₂ absorber 104 is directed to the sweetCO₂ stripper 100 where the CO₂ is stripped from the CO₂ -rich solvent byN₂ stream 102. The sweet CO₂ stripper pressure is about 300 psig±100psig, preferably about 300 psig±50 psig.

The CO₂ and N₂ product stream 108 exits from the sweet CO₂ stripper 100and is sent to the combustion turbine (not shown).

Depending upon the quantity of nitrogen available and level of CO₂desired in the H₂, it may be desirable to enhance the stripping of theCO₂ from the solvent 106 by heating the solvent prior to entering thesweet CO₂ stripper 100 and/or by flashing the stripped solvent 92 atatmospheric pressure after exiting the sweet CO₂ stripper 100.

However, it is preferred that these options not be used since heatingrequires additional equipment and cooling of the solvent. Flashing atatmospheric pressure vents the CO₂ and makes it unavailable to generatepower in the gas turbine. Nevertheless, depending upon economicoptimizations, these options may be attractive for specific cases.

This process also has the benefit of producing a concentrated stream 74of H₂ S. The utilization of a CO₂ stripper using nitrogen or some othernon-soluble gas, such as H₂, after preheating the rich solvent isextremely effective in minimizing the CO₂ in the gas going to the Clausunit (not shown) to recover the sulfur values. An H₂ S purity of greaterthan 50% can be obtained using this process. This high concentration ofH₂ S eliminates the need for special handling of the sour gas in theClaus unit and helps reduce the Claus unit size and cost.

A flash drum (not shown) between the sour CO₂ stripper 20 and the H₂ Sstripper 46 can be used to eliminate additional CO₂ and stripping gas.This can produce an H₂ S concentration greater than 95%. However, therelatively small amounts of CO₂ remaining in the solvent after strippingprovide a flash gas relatively rich in H₂ S and lean in CO₂ and thisflash gas requires a compressor to recover the sour gas flashed at thelower pressure along with the CO₂.

Alternatively, a lower pressure sour CO₂ stripper can also be used inplace of or in addition to the high pressure (1000 psig) sour CO₂stripper 20 described in FIG. 3. The gas coming from the low pressurestripper is cleaned with a secondary absorber and then routed at about300 psig±100 psig, preferably about 300 psig±50 psig to the combustionturbine (not shown) as described in FIGS. 1 and 2. The advantage ofhaving a second sour CO₂ stripper operating at approximately 300 psig isthe reduced gas flow which would need to be cleaned in the secondaryabsorber.

In another embodiment, the high pressure sour CO₂ stripper can bereplaced with a flash drum at approximately 1000±300 psig, preferablyabout 1000 psig±150 psig followed by an approximately 300 psig±100 psig,preferably about 300 psig±50 psig stripper as shown in FIG. 2.

What is claimed is:
 1. An integrated process for the separation,recovery and utilization of acidic gases comprising H₂ S, COS and CO₂contained in a raw synthesis gas produced from the high pressure partialoxidation of a hydrocarbonaceous reactant, comprising:(a) contacting theraw synthesis gas with a first liquid solvent in a first acidic gasremoval unit to selectively absorb and remove at least a portion of theacidic gas from the raw synthesis gas and produce a purified synthesisgas; (b) selectively removing CO₂ from the first liquid solvent bystripping the liquid solvent with N₂ in a CO₂ stripper to selectivelyremove the CO₂ and form a first CO₂ -rich nitrogen gaseous mixture and afirst solvent residue containing H₂ S and COS, wherein the pressure ofthe liquid solvent is reduced prior to entering the stripper; (c)purifying the first solvent residue containing H₂ S and COS to recoverthe sulfur values; (d) purifying the first CO₂ -rich nitrogen gaseousmixture by contacting it with a second liquid solvent in a second acidicgas removal unit to remove residual H₂ S and COS and to produce apurified CO₂ -rich nitrogen gaseous mixture and a second solvent residuecontaining H₂ S and COS; and (e) introducing the purified CO₂ -richnitrogen gaseous mixture without further compression into a combustionturbine to produce power, wherein it is contacted with the purifiedsynthesis gas and serves as a moderator during the combustion of saidsynthesis gas.
 2. The method of claim 1, wherein a portion of the CO₂and the H₂ S content of the first liquid solvent is flashed off prior tothe stripping treatment of step (b).
 3. The method of claim 2, whereinthe CO₂ and H₂ S flashed off is contacted with the raw synthesis gasprior to step (a).
 4. An integrated process for the separation, recoveryand utilization of acidic gases comprising H₂ S, COS and CO₂ containedin a first separate stream of raw shifted synthesis gas and a secondseparate stream of raw unshifted synthesis comprising:(a) contacting theraw shifted synthesis gas with a liquid solvent to selectively absorband remove the acidic gases from the raw shifted synthesis gas, and toproduce a first acid-rich liquid solvent and an acidic gas-depletedshifted synthesis gas; (b) contacting the raw unshifted synthesis gaswith the first acid-rich liquid solvent to selectively absorb and removethe acidic gases from the raw unshifted synthesis gas, and produce apurified unshifted synthesis gas and a second acid-rich liquid solvent;(c) contacting the acidic gas-depleted shifted synthesis gas with afirst CO₂ absorbent solvent, to produce a sweet shifted synthesis gas,and a first CO₂ -rich solvent; (d) selectively removing CO₂ from thefirst CO₂ -rich solvent by stripping said solvent with N₂ gas to producea first CO₂ -rich nitrogen gaseous mixture and a first regenerated CO₂-absorbent solvent; (e) introducing the first CO₂ -rich nitrogen gaseousmixture without further compression into a combustion turbine to producepower, wherein it is contacted with the purified unshifted synthesis gasto serve as a moderator during the combustion of said purified unshiftedsynthesis gas; (f) selectively removing CO₂ from the second acid-richliquid solvent by stripping said solvent with N₂ gas to produce a secondCO₂ -rich nitrogen gaseous mixture and a first H₂ S-rich liquid solvent;and (g) contracting the second CO₂ -rich nitrogen gaseous mixture withthe raw unshifted synthesis gas.
 5. The process of claim 4, wherein afirst portion of the first CO₂ -rich solvent is used to contact the rawshifted synthesis gas in step (a).
 6. The process of claim 4, wherein asecond portion of the first CO₂ -rich solvent is used to contact the rawunshifted synthesis gas in step (b).
 7. The process of claim 4, whereinH₂ S is removed from the first H₂ S-rich solvent in an H₂ S stripper toproduce gaseous H₂ S and a first regenerated H₂ S-absorbent solvent. 8.The process of claim 7, wherein the first regenerated H₂ S-absorbentsolvent is used to contact the sweet shifted synthesis gas in step (c).9. The process of claim 4, wherein the sweet shifted synthesis gas fromstep (c) is subjected to a pressure swing absorption to extract hydrogenout of the sweet shifted synthesis gas or other hydrogen extractionprocess.
 10. The process of claim 7, wherein the H₂ S is processed torecover sulfur values.